1. Field of the Invention
This invention relates to the field of crude oil production. Particularly, the invention relates to enhanced oil recovery in medium to heavy oil reservoirs by thermal flooding.
2. Description of Related Art
Heavy crude oil reservoirs are generally more difficult to develop than reservoirs of lighter crude oil. Heavy petroleum deposits contain crude oil of relatively high density. The density of a crude oil is generally represented by its API gravity--defined by the American Petroleum Institute (API) as .degree. API=[141.5/specific gravity]-131.5, where the specific gravity is measured at 60.degree. F. Crude oil produced from heavy crude oil deposits generally have an average API gravity of 25 or less; from medium deposits, 30 or less. API gravity is inversely proportional to density: the higher the API gravity, the lower the density. Lower density is generally associated with higher viscosity, i.e., greater resistance to flow. Heavier crude oil deposits--having high viscosity--do not flow readily and are difficult to develop. This raises production costs.
Researchers therefore seek methods of improving recovery of heavy petroleum deposits. Crude oil is held in a reservoir by viscous forces (resistance to flow) and capillary forces. Viscous forces predominate in heavy oil reservoirs. Heavy oil reservoir enhanced recovery processes generally focus on reducing viscosity to improve oil mobility.
Hot water flooding is an enhanced recovery process that uses heat to improve conventional water flooding. The higher temperature lowers the viscosity of the heavy oil; the oil then flows more easily to the production well. Hot water flooding is generally inefficient and unpopular. Steam flooding is another recovery process that is used to improve conventional flooding. But steam flooding is not suitable for some heavy oil reservoirs, e.g., where: (1) the heavy oil is of very high viscosity, (2) the reservoir is at too high a pressure to develop a steam gas phase, or (3) the formation of a steam chest is undesirable for environmental reasons. This has made the process less popular for oil recovery.
Solvent-in-water injection is another enhanced recovery process. This process seeks to improve recovery efficiency by lowering capillary forces. Solvent is injected into a reservoir as a slug--a discrete volume of fluid of composition different from the injection fluid. The solvent slug mixes with water and oil and displaces both. This process uses solvents mutually soluble in water and oil to effect a miscible to nearly-miscible type displacement process in light to medium oil reservoirs (&gt;25.degree. API). U.S. Pat. No. 4,629,000 discloses injecting a slug containing an oil-soluble alcohol of 5 to 7 carbon atoms and an oil-soluble sulfate or sulfonate surfactant. The injection fluid is not heated.
Yet another enhanced recovery process is aromatic hydrocarbon injection. U.S. Pat. No. 3,608,638 discloses a method to enhance oil recovery from tar sands using hot hydrocarbon solvents. The solvents are injected at temperatures between 300.degree. F. and 700.degree. F. Preferred solvents are aromatic hydrocarbons. U.S. Pat. No. 4,004,636 and U.S. Pat. No. 4,109,720 disclose petroleum recovery methods using multiple-component solvent injection.
Laboratory studies performed using the methods described above showed that oil recoveries declined as the oil gravity decreased and viscosity increased. This suggests that these process are not suitable for heavy oil recovery. Additionally, solvent injection processes are costly, since large amounts of relatively expensive solvent are consumed.
Another conventional process improves recovery by including surfactants in a water injection process. As with solvent slug processes, a disadvantage is higher cost. U.S. Pat. No. 3,977,471 discloses an oil recovery method using an injection fluid containing brine, a sulfonate surfactant, and an alcohol co-surfactant. The process is not carried out at elevated temperature, since the surfactants lose surface activity under reservoir conditions of high temperature (120.degree. F. or more). The process uses alcohols as co-surfactants to improve surface activity in brine of high salinity. U.S. Pat. No. 4,018,278 addresses the problem of temperature instability of salts of polyethoxylated alcohols, polyethoxylated alkylphenols and alkylphenol sulfates, and the problem of poor performance of alkyl and alkylaryl sulfonates in water of high salinity, by using sulfonated, ethoxylated alcohols or alkylphenols having alkyl or alkylaryl groups of 8 to 20 carbons. These processes all suffer the disadvantage of requiring costly surfactants.
Carbon dioxide flooding is another conventional process for improved crude oil recovery. U.S. Pat. No. 4,899,817 discloses the use of alcohol in solvent flooding by carbon dioxide. To reduce the cost of the process, a slug of carbon dioxide and alcohol is injected, followed by injection of water. The alcohol reportedly increases the viscosity and density of the carbon dioxide. The process is not simple--it requires careful control of pressure to maintain the carbon dioxide under supercritical conditions. U.S. Pat. No. 5,333,687 discloses carbon dioxide flooding with a surfactant foaming agent and alcohols of 8 to 20 carbons. Alcohols of fewer than 8 carbons are discouraged as having less interfacial activity, The added alcohol allows cost reduction by replacing the expensive surfactant foaming agent. But surfactant must still be present in an alcohol/surfactant ratio of at least 1:2.
Therefore, there is a need in the art for a lower cost process that improves the efficiency of oil recovery. Particularly, there is a need for a more cost effective hot water flooding process that improves the efficiency of oil recovery, especially the recovery of heavy oils. A process is therefore sought to enhance at lower cost the efficiency of oil recovery by hot water flooding. The present invention, for which a full description is presented below, solves the need in the art for such a process.